Truck-mounted pumping system for treating a subterranean formation via a well with a mixture of liquids

ABSTRACT

An efficient truck-mounted injection system for injecting a combined aqueous or hydrocarbon-based liquid stream and a liquid carbon dioxide stream via a well into a subterranean formation.

RELATED CASES

This is a divisional of application Ser. No. 12/381,204 filed Mar. 9,2009 by Randal L. Decker.

FIELD OF THE INVENTION

The present invention relates to an efficient truck-mounted injectionsystem for injecting an aqueous or hydrocarbon-based liquid stream or amixed aqueous and hydrocarbon-based liquid stream and a liquid carbondioxide stream via a well into a subterranean formation.

BACKGROUND OF THE INVENTION

In the use of liquid carbon dioxide for injection with various liquidwell treating materials, it has been necessary in the past to use twohigh-pressure pumps; one for the injection of an aqueous orhydrocarbon-based liquid stream and one for the liquid carbon dioxidestream to achieve the required injection and mixing pressures.

These high-pressure pumps, which are large pumps, are typically mountedon heavy duty trucks for movement to a well area. These pumps aretypically massive, positive displacement pumps having one or multipleplungers and are used to increase the pressure of injection streams to apressure suitable for injection into a well up to and at or exceedingfracturing conditions as required. The use of these pumps is expensivesince they are subject to a substantial per diem charge as a result ofthe high cost of the pumps, because such pumps have relatively highmaintenance costs and are typically transported separately on truckswhich also incur a substantial per diem charge.

A more efficient and economical way to inject a stream of liquid carbondioxide and a liquid stream of aqueous or hydrocarbon-based liquidtreating solution into a well at a suitable pressure has been sought.

SUMMARY OF THE INVENTION

A truck-mounted system for injecting a mixture of liquids into asubterranean formation via a well extending from an earth surface intothe subterranean formation, the system comprising: a truck having a bedand being adapted to support the system and transport the system for useto inject the mixture of liquids via the well into the subterraneanformation; a first tank positioned on the bed, adapted to contain aquantity of a first liquid and adapted to supply selected quantities ofthe first liquid to the well; a second tank positioned on the bed,adapted to contain a quantity of a second liquid and adapted to supplyselected quantities of the second liquid to the well; a first pumpsupported by the bed in fluid communication with the first tank andadapted to pump selected quantities of the first liquid to a firstselected intermediate pressure; a second pump supported by the bed influid communication with the second tank and adapted to pump selectedquantities of the second liquid to a second selected intermediatepressure; and, a third pump supported by the truck bed, in fluidcommunication with the first pump and the second pump and adapted topump the liquid mixture into the well at a pressure higher than thefirst and second selected intermediate pressure.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic diagram of a prior art system for injecting amixture of a treating solution and liquid carbon dioxide;

FIG. 2 is a schematic diagram of a system for supplying a composition ofthe treating solution and liquid carbon dioxide to a well;

FIG. 3 is a graph showing test results from the tests described herein;

FIG. 4 is a graph showing the results achieved by the use of aconventional process, which was tested in comparison to the process fortreating a formation;

FIG. 5 shows a schematic diagram of a prior art system for injecting amixture of a treating solution and liquid carbon dioxide;

FIG. 6 is a schematic diagram of an embodiment of the present invention;

FIG. 7 is a detailed schematic diagram of an embodiment of the presentinvention; and,

FIG. 8 is a detailed schematic diagram of an embodiment of the presentinvention mounted on a straight body truck.

DESCRIPTION OF PREFERRED EMBODIMENTS

In the discussion of the Figures and embodiments, various features suchas pumps, valves and the like necessary to achieve the flows requiredand discussed are shown schematically for simplicity since such featuresare considered to be well known to those skilled in the art.

In the description of the present invention, detailed descriptions ofthe equipment used are not included since they are not necessary to thedescription of the present invention and include well-known equipment.

In FIG. 1 a subterranean formation 10, which is to be treated is shown.Subterranean formation 10 underlies an overburden 12 and an earthsurface 14. Subterranean formation 10 is penetrated by a well 16, whichincludes tubing 18 and a packer 20 to enable the injection of a treatingliquid into subterranean formation 10. Well 16, while not described indetail, is a cased well and includes perforations 22, extending from aninside of the well into subterranean formation 10. A bottom 24 of thewell may be in or directly beneath subterranean formation 10 or well 16may extend into subterranean formations lying beneath subterraneanformation 10. If so, it is desired that subterranean formation 10 beisolated, as well known to those skilled in the art, for treatment.

In FIG. 2 a system 30 is shown for producing the composition forinjection into well 16. The system comprises a line 32, which is influid communication with a system for mixing the components via line 32and a check valve 54 and a well 16. An acid pump 34 is shown incommunication via a line 38 with an acid supply 36 to supply aqueousacid via a line 40 at a desired pressure and rate to line 32. Similarly,a liquid CO₂ pump 42 is shown in communication with a liquid CO₂ supply44 via a line 46 so that liquid CO₂ is desirably pumped via a line 48into line 32. Line 32 includes a line 50 and a pressure valve 52 for therelief of pressure if desired. It will be understood that the aqueousacid supply and the liquid CO₂ supply could be originally provided atpressure so that it would be unnecessary to have pumps for either orboth. Such variations are considered to be well within the scope of thepresent invention.

According to the present invention, the treating fluid is mixed withliquid CO₂ to produce an injection liquid containing from about 51 toabout 95 weight percent liquid CO₂. Preferably, the liquid CO₂ ispresent in a weight percentage from about 60 to about 80. The resultinginjection liquid is injected into the subterranean formation, which isthen shut in for at least one hour.

The treating fluid may be any well-treating material such as an acid, acorrosion inhibitor, a solvent or a scale inhibitor. The acid may be anysuitable inorganic or organic acid, such as acids selected from thegroup consisting of hydrochloric, perchloric, nitric, sulfuric,phosphoric, hydrobromic, hydrofluoric, hydriodic, citric, acetic and thelike. Substantially any suitable acid can be used, so long as it iscompatible with the subterranean formation and effective to dissolvesmall portions of the formation or otherwise treat the formation asdesired. The acid is mixed with liquid CO₂ in an amount from about 51 toabout 95 weight percent to produce a composition comprising about 51 toabout 95 weight percent liquid CO₂ and from about 5 to about 49 weightpercent aqueous acid. The acid may be provided as an aqueous solutionsuch as hydrochloric acid, which is frequently marketed inconcentrations of about 3.0 to about 28 volume percent in aqueoussolution. The weight references herein are to the acid in the form inwhich it is supplied and injected. In other words, a 15 volume percenthydrochloric acid in aqueous solution would be injected in an amountequal to the stated weight percent of the aqueous solution. Similarconsideration is applied to the other acids used.

The liquid CO₂ is pumped at temperatures typically from about −10 toabout 5° F., but may be pumped at temperatures from about −15 to about10° F. The liquid CO₂ may be pumped at any suitable temperature andpressure at which the CO₂ is liquid. In other words, at higher pressuresthe temperature of the liquid CO₂ can be higher. The liquid CO₂ and theaqueous acid are physically mixed at the wellhead or at the pumpdischarge or the like. The liquid CO₂ is quite soluble in the acids andthey form a microemulsion that has a viscosity of about 20 to about 90centipoises and a lower relative permeability than plain acid. Testinghas indicated that plain acid has a relative permeability of about 4millidarcy (md), while the CO₂ foamed acid had a relative permeabilityof 0.3 md for the acid component (a decrease of over 13 times or 1300%)while the relative permeability to the CO₂ component was 0.2 md (adecrease of 20 times or 2000%) depending upon the amount of liquid CO₂used. The much lower relative permeability, and conversely higherviscosity, are critical in reducing acid leak-off near the wellbore andthereby causing the formation of a main flow channel for the acid topenetrate deeper into the formation than non-foamed and/or low viscosityacids.

Generally speaking higher concentrations of liquid CO₂ result in ahigher viscosity. This higher viscosity in the liquid CO₂/treatingliquid microemulsion acts as a fluid loss agent preventing leak off ofthe acid from the near wellbore. The injection mixture forms one or moremain flow channels (worm holes) in the formation so that themicroemulsion is pushed deeper into the formation by the injection oflesser volumes than by the injection of the acid or other materialalone. The microemulsion is forced deeper into the formation and reachesthe areas of the reservoir which have not been previously produced ordepleted. Once the microemulsion is in place, it tends to release theacid or other treating material into the subterranean formation for itsinteraction with the formation.

Desirably the acid optionally contains a foaming agent, which may be anysuitable foaming agent compatible with the subterranean formation andthe acid. For instance, some suitable foaming agents are shown in U.S.Pat. No. 4,737,296 issued Apr. 12, 1998 to David R. Watkins. The foamingagent may comprise a surfactant system as disclosed in U.S. Pat. No.4,650,000 issued Mar. 17, 1987 to Eva M. Andreasson, et al. Additionalfoaming agents for foaming and stabilizing acidizing fluids aredisclosed in U.S. Pat. No. 6,555,505 issued Apr. 29, 2003 to Karen L.King, et al. These patents are hereby incorporated in their entirety byreference.

As indicated previously, substantially any suitable foaming agentcompatible with the liquid CO₂ and the treating fluid is effective.

Further it is desirable that the acid contains quantities of methanol.While the presence of methanol is optional, it is desired that themethanol be present in an amount from about 5 to about 25 weight percentin the preferred composition.

The composition of the present invention can be used to inject acid,organic solvents, scale inhibitors or corrosion inhibitors into theformation. While acidizing is a commonly used treatment which is greatlyimproved by the process and composition of the present invention, it isnoted that in some instances it is desirable to inject organic solventsinto a subterranean formation to remove materials such as, for instance,asphaltenes deposited near a production wellbore or at production siteswithin the formation at which hydrocarbons are released into a permeableflow path into a wellbore or the like. Similarly, scale inhibitors arefrequently injected for a substantial distance into the formation toinhibit the formation of scale as water, oil or gas components arereleased from the formation with the resulting formation of scale in thepores from which they are released and through which they pass. It isquite commonly necessary to inject a scale inhibitor to maintainproduction in a subterranean formation. Such scale inhibitor injectionsmay be made after an acid treatment to remove scale or the like, asknown to those skilled in the art. Further, corrosion inhibitors maydesirably be injected to inhibit corrosion of well components as fluidsare produced through such well components. In other words, the injectionof the corrosion inhibitors a substantial distance into the formationresults in the production of the corrosion inhibitor in trace quantities(which may be sufficient to inhibit corrosion in the well equipment)with the produced fluids

The method of the present invention comprises forming the compositionand injecting it into the subterranean formation and thereafter shuttingin the well for at least one hour.

As discussed previously, the microemulsion has much lower interfacialtension and a higher viscosity than the acid without the addition of theliquid CO₂. These two qualities combine to give the microemulsion theability to penetrate deeply into the subterranean formation. The mixtureis pumped into the well at pressures adequate to inject it into theformation. The quantity injected will be determined by the pore volumewhich it is desired to treat. Particularly when acids are injected butin general with all the materials, the treating materials will have aninteraction with the formation rock to dissolve, clean, treat orotherwise modify the rock's ability to produce oil, gas, water or thelike. The mixture is pumped into the well at pressures below fracturingpressure, but adequate to inject it into the formation as noted and in avolume sufficient to treat the volume of the well which is desired to betreated. If it is desired to push the composition deeply into the well,a slug containing from 0 to about 100 weight percent liquid CO₂ and fromabout 0 to about 100 weight percent water or crude oil may be used forinjection into the well to push the composition further into theformation. Desirably once the composition is in place, it is left inplace for a period of time to absorb heat from the formation andgenerate foam. The foam then moves out into formation portions whichhave not previously been treated. Desirably the composition is left inplace in the formation for at least one hour and preferably up to 4hours or longer.

With the formation shut in, the foam is pushed into areas of theformation which have not previously been treated from the flow pathcreated by the injection of the composition by the increased pressure inthe well.

Placing the composition in the subterranean formation, as discussedabove, when corrosion inhibitors or scale inhibitors are used, resultsin positioning these materials in the formation so that they can beproduced back with the materials produced from the formation to inhibitcorrosion of well tubulars, which include rods, tubing, casing, packers,bridge plugs and subsurface pumping equipment and the like. Similarly,the use of scale inhibitors not only inhibits scale formation in theformation but also on the components of the well.

The composition of the present invention comprises from about 51 toabout 95 weight percent liquid CO₂ and from about 5 to about 49 weightpercent of a treating fluid. The treating fluid, as indicatedpreviously, may be an aqueous acid, an inorganic solvent, a scaleinhibitor or a corrosion inhibitor, or any other desired treating fluidor mixtures thereof. The present method and composition are directed toa carrier composition which is useful to carry treating fluids into asubterranean formation more efficiently and more effectively than hasbeen previously possible.

Desirably the composition contains from about 60 to about 80 weightpercent CO₂ in the composition. As indicated, increased quantities ofliquid CO₂ result in increased viscosity and more effective movement ina slug fashion through the formation.

Desirably in the composition, the treating liquid is at least one of aninorganic acid, an organic acid, an organic solvent, a scale inhibitoror a corrosion inhibitor or the like. Typically the acid is selectedfrom the group consisting of hydrochloric, perchloric, nitric, sulfuric,phosphoric, hydrobromic, hydrofluoric, hydriodic, citric, acetic andcombinations thereof. Further the composition also desirably containsfrom about 5 to about 25 weight percent methanol and from about 0.2 toabout 1.0 weight percent of a foaming agent. The composition typicallyhas a viscosity from about 20 to about 90 centipoise and preferably fromabout 60 to about 90 centipoise.

Experimental Procedures

Formation samples were extracted of hydrocarbons, leached of salts anddried until the weight stabilized. Basic properties, including graindensity, pore volume and permeability to air were measured at 1400 psinet confining stress.

Synthetic formation brine was prepared based on the analysis of theformation brine using deionized water and reagent grade chemicals. Thesynthetic formation brine was filtered to 0.45 microns and degassed.Fluid parameters including viscosity and density were measured at 135°F.

Samples were evacuated of air and pressure saturated with syntheticformation brine. Saturation percent was calculated gravimetrically.

Each sample was loaded into a centrifuge in an air-displacing-brineconfiguration. The samples were desaturated at a capillary pressureequivalent to 200 psi. Initial water saturation was calculatedgravimetrically.

Each sample was briefly saturated with depolarized kerosene.

Each sample was loaded into a hydrostatic coreholder and 1400 psi netconfining stress was applied. A pore pressure of 200 psi was establishedby passing depolarized kerosene through the system and around thesample. Coreholder, sample and system were elevated to 135° F. whilemaintaining net confining stress and pore pressure and allowed toequilibrate for four (4) hours.

Crude oil was injected through each sample at a constant rate todisplace the depolarized kerosene. Once the depolarized kerosene wasdisplaced and the differential pressure stabilized, effectivepermeability to oil at initial water saturation was determined.

The temperature was reduced to ambierit while bypassing crude oilthrough the system and around the sample. The pore pressure was slowlyremoved and each sample was unloaded from the coreholder.

Each sample was loaded into an aging vessel, covered with crude oil andpressurized to 500 psi. The samples were allowed to age for one week at135° F. while temperature and pressure were monitored. After wetabilityrestoration, the vessel was cooled to ambient temperature and thepressure was slowly lowered. Each sample was removed for flow testing.

Each sample was loaded into a hydrostatic coreholder and 1400 psi netconfining stress was applied. A pore pressure of 3800 psi wasestablished by passing depolarized kerosene through a system and aroundthe sample while maintaining 1400 psi net confiding stress. Coreholder,sample and system were elevated to 135° F. while maintaining netconfining stress and pore pressure and allowed to equilibrate for four(4) hours.

Synthetic formation brine was injected through each sample at a constantrate, while collecting produced volumes of water and oil and monitoringdifferential pressure and elapsed time until a water-cut of 99.95% orgreater was observed. Effective permeability to brine at residual oilsaturation was determined at two injection pressures.

Fifteen percent hydrochloric acid and additives (sample 3C) wereinjected in the injection direction at a constant rate of 0.25 cc/min.Differential pressure, injected and produced volumes and injectionpressure were recorded versus time. When a sudden and sharp decrease indifferential pressure was noted, a worm hole had been established (FIG.3).

Fifteen percent hydrochloric acid, additives, foamer and carbon dioxidewere co-injected through a second sample (sample 3) in the injectiondirection at a constant rate of 0.25 cc/min. They were co-injected at an80:20 carbon dioxide to acid ratio. Differential pressure, injected andproduced volumes and injection pressure were recorded versus time. Whena sudden and sharp decrease in differential pressure was noted, a wormhole had been established (FIG. 4).

The test system and sample were allowed to cool to ambient temperature.Pore pressure and net confining stress were slowly removed. Each samplewas unloaded from the hydrostatic coreholder, weighed, extracted ofhydrocarbons, leached of salts and dried to a constant weight.

Permeability versus throughput data was calculated based upon sample andfluid parameters and data collected using Darcy's Law. Worm holepenetration is calculated from the total amount of fluid injected versustime.

By the method and by the use of the composition of the present inventionas shown in FIG. 4, it will be noted that by the use of the compositionof the present invention, the formation as treated has exhibited acomparable initial permeability to the tests shown in FIG. 4 withinjection being at the differential pressure shown. By the injection ofonly four pore volumes of treating solution into the formation, thetreating composition has passed through the formation leaving a treatedzone in the formation from the injection point to a receiving well sothat the formation is treated throughout with only four pore volumes ofthe composition. By direct comparison, when an aqueous acid alone isused, as shown in FIG. 3, it required 36 pore volumes of material toposition the injected acid completely through the formation to areceiving well. The invention represents a significant improvement inthe expense and the effectiveness of the acid to treat the subterraneanformation

A prior art well treating system 10 is shown in FIG. 5.

In FIG. 5 a hydrochloric acid solution source is shown as an HCLtransport 12 and a water source is shown as a water transport 16. Thesetransports are typically large tanker trucks or the like which can bemoved to a well site for treatment of the well. Typically a truck isused for the aqueous acid. Another truck is used for the liquid carbondioxide and another and possibly more than one other truck will be usedto deliver and support the pumps and their power sources. These trucksare subject to per diem charges for the time required to complete thewell treatment. Typically these are trucks which discharge their cargosat a pressure from atmospheric pressure, to a booster pump (not shown)that increases the liquid pressure to about 50-150 psia as shown withwater and acid solution being passed through lines 14 and 18 to ahigh-pressure pump 20. The high-pressure pump 20 increases the pressureof the streams to a pressure sufficient for discharge into a well 24 viaa line 22.

Liquid carbon dioxide is typically delivered by trucks, shown as CO₂transports 26 and is typically supplied at about 250-300 psia pressure.The carbon dioxide is typically passed to a liquid carbon dioxidebooster pump 32 through one of lines 28 and 30. Booster pump 32increases the pressure of the liquid carbon dioxide stream by about 50to about 75 psia and passes it to a high-pressure pump 36 whichincreases the pressure of the carbon dioxide stream and discharges theliquid carbon dioxide stream through a line 38 to well 24. The streamsare mixed in well 24 as they pass downwardly through the well.

In FIG. 6 a schematic diagram of an embodiment 100 of the presentinvention is shown wherein an aqueous hydrochloric acid liquid is storedat atmospheric pressure. The liquid carbon dioxide is stored at 250-300psia. In this embodiment, liquid carbon dioxide is stored in a vessel124 and is produced through a line 126 and passed through a vaporseparator 136 and then through a line 138 to a CO₂ booster pump 140where it is compressed to a pressure up to about 600 psia. The streamcompressed in booster pump 140 is passed through a line 142 and thenthrough a line 116 to a high-pressure pump 118. The temperature,pressure and flowrate are measured by instruments 116 a, 116 b and 116 cand instruments 120 a, 120 b and 120 c for lines 116 and line 120respectively. The high-pressure pump then increases the pressure in thisstream along with the aqueous acidic liquid stream for injection througha line 120 to a well 122.

The aqueous acid liquid is stored in storage 102 and passed via a line108 which includes a valve 108 a to a liquid booster pump 110 where itspressure is increased to a pressure of about 600 psia and then combinedvia a line 112 with the stream from line 142 and fed to a high-pressurepump 118 via line 116. Liquid booster pump 110 also is in fluidcommunication with a recycle loop comprising a line 112 and a line 114,which includes a valve 144 a and a vapor trap 114 b; so that the outputfrom liquid booster pump 110 can be recycled if desired in whole or inpart for pressure and flow volume control.

Vapor separator 136 operates to remove accumulated vapor that has beenformed by the absorption of heat as the liquid carbon dioxide has beenmoved from storage 124 via line 126. The vapor may be vented to theatmosphere from the top of separator 136 via a line 147, therebypreventing the booster pump 140 and high-pressure pump 118 fromcavitating. In the event that the liquid CO₂ rate must be reduced topump 118, a portion of the stream in line 142 can be diverted through aline 144, which includes a valve 144 a, and can be re-cycled throughvapor separator 136 which will remove accumulated vapor and aid incontrolling liquid CO₂ pump 140 rate and pressure from pump 140 tohigh-pressure pump 116. The stream is then passed through a line 146back to line 142 or discharged via line 147. This enables the operationof vapor separator 136 to separate vapor from the liquid carbon dioxideas required. As indicated, it is contemplated that the vapor separatorwill contain only relatively small volumes of carbon dioxide vapor atany given time since substantial amounts of carbon dioxide liquid arepassing through these vessels.

This embodiment allows the liquid carbon dioxide to be in storage at250-300 psia and allows for the aqueous hydrochloric acid to be instorage at atmospheric pressure. According to the present invention, theliquid treating fluid and the carbon dioxide are supplied to a singlehigh-pressure pump at a pressure of about 550 psia, up to 650 psia, andat preferably about 600 psia. In the past it has been considerednecessary to have a high-pressure pump for each of the liquid treatingsolution and the liquid carbon dioxide.

In the embodiment of FIG. 6 only a single high-pressure pump is used.This results in a substantial increase in the process efficiency sincebetter emulsification is achieved. It also results in a substantialreduction of expense in that only one high-pressure pump is required tobe maintained and operated on site. The resulting emulsions are formedin the high-pressure pump and the emulsion is pumped into the well at apressure great than 650 psia.

While the invention has been discussed above by reference to aqueoushydrochloric acid as a treating solution, it should be understood thatthe acid solution may contain methanol and other additives. While thepresence of methanol is optional it is desirable in many instances thatthe methanol be present in an amount from about 5 to about 25 weightpercent in the treating liquid. Further the invention can be used toinject not only aqueous acid but organic solvents, hydrocarbon-basedscale inhibitors, corrosion inhibitors and the like into the well aloneor with the aqueous acid. The only real limitation on the use of thetreating liquid is that it be liquid when mixed the liquid carbondioxide.

As well known to those skilled in the art, whatever arrangement is usedto provide the liquid carbon dioxide to the high-pressure pump at thedesired pressure must maintain the liquid carbon dioxide under suitabletemperature and pressure conditions to maintain it in a liquid state.Such conditions are well known to those skilled in the art.

While the embodiments shown are preferred, it is considered necessaryfor the practice of the present invention that the carbon dioxide bedelivered in a liquid form at a pressure from about 550 psia, up to 650psia, to the high-pressure pump along with the aqueous solution whichmust be delivered at the same or a comparable pressure and at atemperature which does not result in vaporization of the liquid carbondioxide. These streams may be introduced in mixture or alone into thehigh-pressure pump. In either event the resulting emulsion is readilypumped by the high-pressure pump into the well as shown, for instance inFIG. 6, via line 120 into well 122.

As mentioned previously, the high-pressure pumps are typically large,positive displacement pumps having from 1 to 5 or more plungers whichare relatively high maintenance and high expense pumps for use becauseof their ability to generate the extreme pressures used in fracturingoperations and the like. These positive displacement pumps are suitableas the high-pressure pump in the present invention.

Multi-stage centrifugal pumps may be used for similar applications butare not typically used or preferred for fracturing operations. They aresuitable for use as the high-pressure pump in the present invention solong as they are capable of mixing the aqueous solution and the liquidcarbon dioxide and injecting the resulting mixture into a well at apressure greater than about 650 psia.

While typical and preferred operating conditions for this embodimenthave been described above, the aqueous liquid solution could be passedto the high-pressure pump at a higher or lower pressure and thehigher-pressure pump is capable of compressing the mixture to pressuresmuch higher than 650 psia. The liquid booster pumps and the feed pumps,if used, may be centrifugal pumps, multi-stage centrifugal pumps and thelike as required to achieve the desired pressure increases. Theoperation of such pumps is much less expensive than for thehigh-pressure pumps and the maintenance requirements for such pumps aremuch lower. The preferred pressures discussed above may be varied solong as the liquid streams are mixed as liquids and so long as thecarbon dioxide is passed to the high pressure pump as a liquid.

By the present invention, the use of a second high-pressure pump hasbeen omitted and improved mixing and operational efficiency has beenachieved in the delivery of the treating liquid/liquid carbon dioxidemixture into the well.

As mentioned previously, it is noted that typically both the aqueousacid or aqueous acid containing hydrocarbon-based materials orhydrocarbon materials may be delivered in a first tank truck with theliquid carbon dioxide being delivered in a second truck. Further thetriplex pumps are relatively large pumps and typically are delivered andoperated from a separate truck. Further the booster pumps may also bedelivered by a third truck. As a result, during the length of thetreatment process, all the trucks are required to remain on-site. Thiscan result in considerable extra expense based upon the requirement forall the separate trucks required to deliver different materials to thewell site. Further, additional expense will be incurred in the event thetrucks are required to spend substantial time on-site while thematerials are used for treatment of a well. In addition to thesedisadvantages the presence of this many vehicles around the vicinity ofthe well can impede operations and be a significant inconvenience.

Accordingly, a preferred embodiment is the use of a truck-mounted systemfor injecting a mixture of liquids into a subterranean formation via awell extending from an earth surface into the subterranean formation.Such a system is shown in FIG. 7. In FIG. 7 a truck-mounted system isshown and comprises a triplex pump positioned to receive a flow of aliquid from a first storage tank and a second stream of liquid carbondioxide from a carbon dioxide storage tank. These materials arecompressed in booster pumps to a pressure suitable for charging to thetriplex pump and subsequently into the well.

FIG. 7, as shown, an injection system 200 is shown on a truck 202 whichcomprises a trailer 204 connected to a tractor trailer cab 206. Thetrailer has a bed 208 and wheels are shown schematically at 210.

It will be understood that while a tractor trailer truck has been shown,a straight truck having a bed of a suitable size could be used as well,as shown in FIG. 8. The use of such a truck enables the use of only asingle truck to deliver all the required components to a well site. Thisreduces the congestion around the well site and reduces the per diemfees if the trucks are required to remain for extended times.

FIG. 8 includes a bed 400 supporting the equipment of the invention asdescribed in FIG. 7, except as shown for FIG. 8. FIG. 8 includes adivider 402 on the bed 400 which separates the equipment of FIG. 7 froma cab 404 which is supported on bed 400. Bed 400 is supported by one ormore pairs of wheels 406.

The system comprises a carbon dioxide storage vessel 212 wherein liquidcarbon dioxide is stored. The storage vessel is supported above bed 208by supports 214. A line 216, including a valve 218, is shown forsupplying liquid carbon dioxide to tank 212. A second line 220,including a valve 222, is also provided and as shown represents apressure relief line. Valve 222 is a pressure relief valve which reducesthe pressure in vessel 212 via line 220 in the event that vessel 212becomes over-pressured.

A line 228, including a valve 230, passes a liquid carbon dioxide streamto a vapor separator 232. This vapor separator may produce a sufficientquantity of vaporous carbon dioxide that it may be discharged to theatmosphere or it may be returned to the liquid carbon dioxide streamdownstream from a pump 238. A liquid stream 234 is withdrawn fromseparator 232 via a line 234 and passed to pump 238 where it iscompressed to a pressure up to about 600-650 psia and discharged througha line 242 including a valve 244. A vapor stream may be recoveredthrough a line 236, a line 315 and a valve 316. Pump 238 also includesline 250, including a valve 252, and line 246, including a valve 248 forpassing a supply of carbon dioxide to pump 238 from an auxiliary sourceof liquid carbon dioxide if necessary. In instances where an extensivewell treatment may require additional liquid carbon dioxide which couldbe supplied by a second truck for a short term continuation ofoperations while the liquid carbon dioxide from the second truck ispassed through pump 238 with the remaining liquid carbon dioxide beingpassed to carbon dioxide storage 212 or the like. Pump 238 is supportedby bed 208 by support 240.

The higher pressure stream recovered from pump 238 is pumped via a line242 through a check valve 298 and combined with a stream of aqueous acidfrom line 270. Temperature, pressure and volume gauges are shown at 288,290 and 292 for monitoring the temperature and pressure in line 242.

The injection fluid, which is typically aqueous hydrochloric acid, isstored in a tank 254. It will be understood that the aqueous acid mayinclude various materials, such as corrosion inhibitors and the like orthat the injection fluid may be a hydrocarbon-based material, such as ahydrocarbon solvent and the like.

The second storage tank 254 is supported by supports 256 and liquid isdischarged from tank 254 via line 258, which includes a valve 265. Aline 262 is in fluid communication with line 258 via a valve 264. Thisline can be used to add materials to the stream in line 258 or toreplenish the amount of injection fluid in tank 254. The stream flowingthrough line 258 is passed to a pump 266 and discharged via a line 270.Pump 262 includes a line 281 including a valve 283 and a line 273 whichincludes a valve 282. Either of these two lines maybe used to chargematerial into pump 270 during operation or to either add materials tothe stream from line 258 or to supply the injection fluid from analternate source or the like. Further line 270 discharges the injectionfluid stream from pump 266 at high pressure. Line 270 includes a valve272, a line 280 including a second valve 282 and a check valve 276. Theflow through line 270 goes into line 242 from pump 238 in a desiredratio as a charge stream to a triplex pump 300. Triplex pump 300 issupported by supports 303. A discharge stream at high pressure (greaterthan about 650 psia) is discharged from triplex pump 300 through a line302, which includes a valve 304 to an injection well (not shown) as theinjection mixture. Pressure gauge 314, temperature gauge 312 andflowmeter 310 are connected to line 302 to monitor the pressure,temperature and flow volume respectively in line 302. An alternate line306 is in fluid communication with line 302 via a valve 308 to divert aportion of the mixture of injection fluid to a second well for other useif desired.

As shown the system includes a recycle line 294 including a valve 296and a vapor trap 310 from line 270 downstream from pump 266 back to pump266 to control the ratio of injection fluid and liquid CO₂ in line 242.A recycle line 243, including a valve 245, is shown to recycle liquidCO₂ from line 242 to vapor separator 232. A vapor line from vaporseparator 232 passes vapor to line 242 downstream of pump 238 or througha line 315 including a valve 316 to discharge.

It will be appreciated that while the lines are shown as closely spacedin FIG. 7, it will be unnecessary to space lines as closely in practicesince the lines can be spaced across the width of bed 204 whereas theymust be shown in two dimensions in the drawings.

By the use of this system, the injection fluids (liquid carbon dioxideand aqueous acid, optionally including treating materials orhydrocarbon-based fluids) are supplied by a single truck used to providepumping facilities necessary to complete the well treatment. The systemis ideally suited to carry out the treatment of a subterranean formationvia a wellbore by the use of a high pressure liquid stream containing amixture of liquid carbon dioxide and a liquid injection fluid. Theapparatus, as shown mounted on a truck, avoids the need for retainingmore than one truck at the injection site and includes facilities forrefilling the liquid carbon dioxide tank and the treating fluid tankfrom other trucks which may be brought to the site if necessary to fillthe tanks after a first treatment for a second treatment of another wellwhich may be in the vicinity or the like. Further, the truck includesall the pumping capacity needed to provide the mixed liquid treatmentfor injection into the well at the conditions required for injection.This represents a significant advantage in reducing the cost of thetreatment, in retaining the flexibility to use materials from separatesources and provide pumping capacity at the facility even if additionalsources are supplied are of one type of fluid or another are required.Further the congestion around the wellbore and the expense for demurrageand the like has been eliminated by this system.

Further the engine of the truck can supply the energy required to drivethe pumps, thereby removing the need to haul an expensive and bulkypower unit to the well. Many advantages are achieved by the use of thetruck-mounted system.

While the present invention has been described by reference to certainof its preferred embodiments, it is pointed out that the embodimentsdescribed are illustrative rather than limiting in nature and that manyvariations and modifications are possible within the scope of thepresent invention. Many such variations and modifications may beconsidered obvious and desirable by those skilled in the art based upona review of the foregoing description of preferred embodiments.

1. A truck-mounted system for injecting a mixture of liquids into asubterranean formation via a well extending from an earth surface intothe subterranean formation, the system comprising: a) a truck having abed and being adapted to support the system and transport the system foruse to inject the mixture of liquids via the well into the subterraneanformation; b) a first tank positioned on the bed, adapted to contain aquantity of a first liquid and adapted to supply selected quantities ofthe first liquid to the well; c) a second tank positioned on the bed,adapted to contain a quantity of a second liquid and adapted to supplyselected quantities of the second liquid to the well; d) a first pumpsupported by the bed in fluid communication with the first tank andadapted to pump selected quantities of the first liquid to a selectedpressure; e) a second pump supported by the bed in fluid communicationwith the second tank and adapted to pump selected quantities of thesecond liquid to a selected pressure; and, f) a third pump supported bythe truck bed, in fluid communication with the first pump and the secondpump and adapted to pump the mixture of liquids into the well at apressure higher than the selected pressure.
 2. The system of claim 1wherein the first liquid is liquid carbon dioxide.
 3. (canceled)
 4. Thesystem of claim 1 wherein the second liquid is a hydrocarbon-basedliquid stream.
 5. The system of claim 1 wherein the truck is a tractorand trailer truck.
 6. The system of claim 1 wherein the truck is astraight body truck.
 7. The system of claim 1 wherein a recycle lineincluding a valve is positioned in fluid communication with a liquiddischarge line from the first pump and a vapor separator.
 8. The systemof claim 1 wherein a vapor separator is positioned in a line from thefirst tank to the first pump.
 9. The system of claim 1 wherein thesystem includes a recycle line including a valve and a vapor trappositioned in fluid communication with a liquid discharge line from thesecond pump and a liquid inlet line to the first pump.
 10. The system ofclaim 1 wherein the third pump is a triplex pump.
 11. The system ofclaim 10 wherein the truck includes an engine adapted to power thetriplex pump.
 12. The system of claim 11 wherein the truck engine isadapted to power at least one of the first pump and the second pump. 13.The system of claim 1 wherein a discharge stream from the third pumpinto the well includes the first liquid and the second liquid in aselected ratio in the mixture of liquids.
 14. The system of claim 1wherein at least one of the first pump and the second pump is supportedby the truck bed in a position beneath the truck bed.
 15. The system ofclaim 1 wherein the first pump is adapted to pump the first liquid to apressure from about 550 to about 650 psia.
 16. The system of claim 1wherein the second pump is adapted to pump the second liquid to apressure from about 550 to about 650 psia.
 17. The system of claim 1wherein the third pump is adapted to pump the mixture of liquids intothe well at pressures greater than 650 psia.
 18. The system of claim 1wherein the first pump and the second pump are centrifugal pumps ormultistage centrifugal pumps.